This section is intended to introduce various aspects of the art, which may be associated with exemplary embodiments of the present disclosure. This discussion is believed to assist in providing a framework to facilitate a better understanding of particular aspects of the present disclosure. Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art.
1. Field of the Invention
The present disclosure relates to the field of hydrocarbon recovery operations. More specifically, the present invention relates to a downhole tool used for treating a wellbore. The application also relates to methods for delivering a chemical treatment to a wellbore below the surface.
2. Technology in the Field of the Invention
In the drilling of oil and gas wells, a wellbore is formed using a drill bit that is urged downwardly at a lower end of a drill string. After drilling to a predetermined depth, the drill string and bit are removed and the wellbore is lined with a string of casing. An annular area is thus formed between the string of casing and the surrounding formations.
A cementing operation is typically conducted in order to fill or “squeeze” the annular area with columns of cement. The combination of cement and casing strengthens the wellbore and facilitates the zonal isolation of the formations behind the casing.
It is common to place several strings of casing having progressively smaller outer diameters into the wellbore. A first string of casing may be referred to as a conductor pipe or surface casing. This casing string serves to isolate and protect the shallower, fresh water-bearing aquifers from contamination by any other wellbore fluids. Surface casing strings are almost always cemented entirely back to the surface.
The process of drilling and then cementing progressively smaller strings of casing is repeated several times until the well has reached total depth. In some instances, the final string of casing is a liner, that is, a string of casing that is not tied back to the surface. The final string of casing, referred to as a production casing, is also typically cemented into place.
Additional tubular bodies may be included in a well completion. These include one or more strings of production tubing placed within the production casing or liner. Each tubing string extends from the surface to a designated depth proximate a production interval, or “pay zone.” Each tubing string may have a packer attached at a lower end. The packer serves to seal off the annular space between the production tubing string(s) and the surrounding casing. In this way production fluids are directed up the tubing string.
In some instances, the pay zones are incapable of flowing fluids to the surface efficiently. When this occurs, the operator may include artificial lift equipment as part of the wellbore completion. Artificial lift equipment may include a downhole pump connected to a surface pumping unit via a string of sucker rods run within the tubing. Alternatively, an electrically-driven submersible pump may be placed at the bottom end of the production tubing. Gas lift valves, plunger lift systems, or various other types of artificial lift equipment and techniques may alternatively be employed to assist fluid flow to the surface.
As part of the completion process, a wellhead is installed at the surface. The wellhead includes piping and valves used for directing the flow of production fluids at the surface. The wellhead also contains wellbore pressures.
Fluid gathering and processing equipment is also provided at the surface. Such equipment may include pipes, valves, separators, dehydrators, gas sweetening units, and oil and water stock tanks. Upon installation of the wellhead and other surface equipment, production may begin.
During the production of hydrocarbons from the pay zones, some wells experience a build-up of scale. This may be due to the presence of dissolved minerals in oil and water produced by oil and gas wells. Changes in temperature and/or pressure which occur as production fluids are pumped from the production zone to the surface can cause the inorganic minerals to come out of solution (“precipitate”) and become deposited on the interior and exterior surfaces of production hardware. Such hardware may include the production tubing, downhole pumps, surface valves, and other equipment.
Scale is typically in the form of a mineral salt that deposits on the surface of metal or other material. Typical scales are calcium carbonate, calcium sulfate, barium sulfate, strontium sulfate, iron sulfide, iron oxides, iron carbonate, the various silicates and phosphates and oxides, or any of a number of compounds insoluble or slightly soluble in water. The presence of mineral salts can also create corrosion on metal surfaces.
In severe conditions, scale creates a significant restriction, or even a plug, in the production tubing and pump orifices. Scale build-up in an artificial lift pump can lead to failure of the pump due to blocked flow passages and broken shafts. In addition, scale can clog perforations, requiring that a well be treated or even re-perforated.
All waters used in well operations can be potential sources of scale. These include water used in waterflood operations and filtrate from completion, workover or treating fluids. For these and the other reasons mentioned, scale removal is a common well-intervention operation.
A wide range of treatment options are available to effect scale removal. These include mechanical removal, chemical treatment, and corrosion inhibitor treatment.
Mechanical removal may be done by means of a pig that is pumped downhole. Alternatively, mechanical removal may involve abrasive jetting that hydraulically cuts scale but leaves the tubing intact. Of course, such mechanical processes do not protect a submersible pump from scale during production operations, nor do they prevent any future build-up of corrosion.
Scale-inhibition treatments involve squeezing a chemical inhibitor into a water-producing zone for subsequent commingling with produced fluids. The scale inhibitor prevents further scale precipitation along producers. However, such a technique is imprecise as it is unknown how much of the inhibitor will make its way back to the wellbore, or when.
Chemical removal is performed by using different solvents according to the type of scale that is presented. Sulfate scales such as gypsum [CaSO42H2O] or anhydrite [CaSO4] can be dissolved using ethylene-diamine tetra-acetic acid (EDTA). Carbonate scales such as calcium carbonate or calcite [CaCO3] can be dissolved with hydrochloric acid [HCl] at temperatures less than 250° F. [121° C.]. Silica scales such as crystallized deposits of chalcedony or amorphous opal normally associated with steam flood projects can be dissolved using hydrofluoric acid [HF]. Chloride scales such as sodium chloride [NaCl] may be dissolved using fresh water or weak acidic solutions, including HCl or acetic acid. Iron scales such as iron sulfide [FeS] or iron oxide [Fe2O3] can usually be dissolved using HCl with sequestering or reducing agents to avoid precipitation of by-products, for example iron hydroxides and elemental sulfur.
In the oil fields of West Texas and other areas where water flooding takes place, calcium sulfate and calcium carbonate scales can appear. Calcium scales such as calcium sulfate, calcium carbonate and calcium oxalate are insoluble in water. However, all three are soluble in a Sodium Bisulfate acid solution. Calcium scale can be removed with an acid wash using a 5 to 15% solution of Sodium Bisulfate (SBS). SBS can also be used during a shutdown to remove scale by re-circulating it throughout areas of the process where needed. The concentration of SBS solutions and the re-circulation time depend on the amount of scale that needs to be removed.
Sulfamic acid (H3NSO3) may also be used in calcium scale (or lime) removal situations. Sulfamic acids include amidosulfonic acid, amidosulfuric acid, aminosulfonic acid, and sulfamidic acid. Sulfuric acids (H2SO4) may also be considered. Sulfamic acids can slowly hydrolyze to ammonium bisulfate in the presence of water.
The delivery of chemical to a wellbore is normally done by placing the chemical in liquid form into the wellbore. However, it is believed that such chemical delivery is frequently ineffective as it is difficult to assure that the treatment is reaching the lowest portions of the wellbore where it is needed most.
Recently, Baker Hughes, Inc. has developed a Sorb™ or ScaleSorb™ process for injecting solid pellets and liquid comprising scale inhibitor or other chemical material into a subsurface formation. The inhibitors are typically injected as part of the initial formation fracturing process. The chemicals treat formation fluids before they arrive at the wellbore. Baker Hughes advertises that its Sorb™ chemicals inhibit scale, paraffin, asphaltenes, and salt; they counteract bacteria and corrosion. However, this process is a one-time injection that depends on the chemical treatment contacting all fluids produced to the wellbore.
Therefore, a need exists for a downhole assembly that will slowly deliver chemical treatment at the level of production perforations, or at or below the level of a pump. Further, a need exists for an assembly and method for using a continuous solid chemical that directly treats a wellbore as the solid material dissolves in the presence of wellbore fluids.